Liquid buildup can occur in aging production wells and can reduce the well's productivity. To handle the buildup, operators can use beam lift pumps or other remedial techniques, such as venting or “blowing down” the well. Unfortunately, these techniques can cause gas losses. Moreover, blowing down the well can produce undesirable methane emissions. In contrast to these techniques, operators can use a plunger lift system, which reduces gas losses and improves well productivity.
A plunger lift system 10 of the prior art is shown in FIG. 1. In the system 10, a plunger 50A disposes in production tubing 16, which deploys in casing 14 from a wellhead 12. During operation, the plunger 50A moves between a lubricator 30 at the surface and a landing bumper 20 downhole. The plunger 50A shown in FIG. 1 is a two-piece plunger. However, a typically plunger 50B as shown in FIG. 2B has a solid or a semi-hollow plunger body 80 with external ribbing 84 or the like for creating a pressure differential.
The two-piece plunger 50A of FIG. 1 allows both pieces to fall faster downhole than would be possible for such a solid or semi-hollow plunger 50B of the prior art. As best shown in FIG. 2A, the two-piece plunger 50A has a separate sleeve 60 and ball 70. The sleeve 60 has an inner bore 62 that defines a seat 68. The ball 70 can fit against the seat 68 and can seal fluid flow up through the plunger's bore 62 during operation. The sleeve's outer surface can have ribbing 64 or the like for creating a pressure differential.
When used in the system 10 of FIG. 1, the sleeve 60 and ball 70 dispose separately in the tubing 16. Operators drop the ball 70 first to land near the bottom of the well. The ball 70 falls into any liquid near the bottom of the well and contacts the bumper 20. Operators drop the sleeve 60 after the ball 70 so it can fall to the bumper 20 as well.
When the sleeve 60 reaches the ball 70, they unite into a single component. With the plunger 50A deployed to handle liquid buildup, operators set the well in operation. Gas from the formation enters through casing perforations 18 and travels up the production tubing 16 to the surface, where it is produced through lines 32/34 at the lubricator 30. Liquids may accumulate in the well and can create back pressure that can slow gas production through the lines 32/34. Using sensors and the like, a controller 36 operates a valve 38 at the lubricator 30 to regulate the buildup of pressure in the tubing 16. Sensing the slowing gas production due to liquid accumulation, the controller 36 shuts-in the well to increase pressure in the well.
As high-pressure gas accumulates, the well reaches a sufficient volume of gas and pressure. Eventually, the gas pressure buildup pushes against the combined sleeve 60 and ball 70 and lifts them together to the lubricator 30 at the surface. The column of liquid accumulated above the plunger 50A likewise moves up the tubing 16 to the surface so that the liquid load can be removed from the well.
In this way, the plunger 50 essentially acts as a piston between liquid and gas in the tubing 16. Gas entering the production string 16 from the formation through the casing perforations 18 acts against the bottom of the plunger 50A (mated sleeve and ball 60/70) and tends to push the plunger 50A uphole. At the same time, any liquid above the plunger 50A will be forced uphole to the surface by the plunger 50A.
As the plunger 50A rises, for example, the controller 36 allows gas and accumulated liquids above the plunger 50A to flow through lines 32/34. Eventually, the plunger 50A reaches a catcher 40 on the lubricator 30 and a spring (not shown) absorbs the upward movement. The catcher 40 captures the plunger's sleeve 60 when it arrives, and the gas that lifted the plunger 50 flows through the lower line 32 to the sales line. A decoupler (not shown) inside the lubricator 30 separates the ball 70 from the sleeve 60. The ball 70 can then immediately fall toward the bottom of the well. The catcher 40 holds the sleeve 60 and then releases the sleeve 60 after the ball 70 is already on its way down the tubing 16.
Dropped in this manner, the sleeve 60 and ball 70 fall independently inside the production tubing 16. The sleeve 60 with its central passage 62 can have gas flow through it as the sleeve 60 falls in the well. On the other hand, flow travels around the outside of the ball 70 as the ball 70 falls in the well. Unfortunately, the ball 70 tends to fall slower than the sleeve 60. Therefore, the system 10 must properly time the dropping of the ball 70 and sleeve 60 so that the ball 70 has sufficient time to fall downhole before the sleeve 60 is allowed to fall. Solutions for decoupling the ball 70 and for timing the dropping of the ball 70 and the sleeve 60 are disclosed in U.S. Pat. Nos. 6,719,060; 6,467,541; and 7,383,878, for example. Although such schemes may be effective, what is needed is a more robust approach with less complexity.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.